Ball catcher apparatus for use in fracturing of formations surrounding horizontal oil and gas wells, and method for using same

ABSTRACT

Following the treatment of formations surrounding an oil, gas or water well, various diameter ceramic balls are retrieved from the downhole equipment by creating a suction force at the earth&#39;s surface to cause such balls to be moved into a ball catcher at the earth&#39;s surface from which the balls can be collected. The suction force is created by a high pressure fluid intersecting a fluid path between the downhole equipment and the ball catcher. The high pressure fluid is preferably operated at, at least 1,000 psi, and even more preferably, between 5,000 and 10,000 psi.

FIELD OF THE INVENTION

The invention relates to a method and apparatus for wellbore fluid treatment and, in particular, to a method and apparatus for selective communication to a wellbore for fluid treatment.

BACKGROUND OF THE INVENTION

An oil or gas well relies on inflow of petroleum products. When drilling an oil or gas well, an operator may decide to leave productive intervals uncased (open hole) to expose porosity and permit unrestricted wellbore inflow of petroleum products. Alternately, the hole may be cased with a liner, which is then perforated to permit inflow through the openings created by perforating.

When natural inflow from the well is not economical, the well may require wellbore treatment termed stimulation. This is accomplished by pumping stimulation fluids such as fracturing fluids, acid, cleaning chemicals and/or proppant laden fluids to improve wellbore inflow.

In one previous method, the well is isolated in segments and each segment is individually treated so that concentrated and controlled fluid treatment can be provided along the wellbore. Often, in this method a tubing string is used with inflatable element packers thereabout which provide for segment isolation. The packers, which are inflated with pressure using a bladder, are used to isolate segments of the well and the tubing is used to convey treatment fluids to the isolated segment. Such inflatable packers may be limited with respect to pressure capabilities as well as durability under high pressure conditions. Generally, the packers are run for a wellbore treatment, but must be moved after each treatment if it is desired to isolate other segments of the well for treatment. This process can be expensive and time consuming. Furthermore, it may require stimulation pumping equipment to be at the well site for long periods of time or for multiple visits. This method can be very time consuming and costly.

Other procedures for stimulation treatments use foam diverters, gelled diverters and/or limited entry procedures through tubulars to distribute fluids. Each of these may or may not be effective in distributing fluids to the desired segments in the wellbore.

The tubing string, which conveys the treatment fluid, can include ports or openings for the fluid to pass therethrough into the borehole. Where more concentrated fluid treatment is desired in one position along the wellbore, a small number of larger ports are used. In another method, where it is desired to distribute treatment fluids over a greater area, a perforated tubing string is used having a plurality of spaced apart perforations through its wall. The perforations can be distributed along the length of the tube or only at selected segments. The open area of each perforation can be pre-selected to control the volume of fluid passing from the tube during use. When fluids are pumped into the liner, a pressure drop is created across the sized ports. The pressure drop causes approximate equal volumes of fluid to exit each port in order to distribute stimulation fluids to desired segments of the well. Where there are significant numbers of perforations, the fluid must be pumped at high rates to achieve a consistent distribution of treatment fluids along the wellbore.

In many previous systems, it is necessary to run the tubing string into the bore hole with the ports or perforations already opened. This is especially true where a distributed application of treatment fluid is desired such that a plurality of ports or perforations must be open at the same time for passage therethrough of fluid. This need to run in a tube already including open perforations can hinder the running operation and limit usefulness of the tubing string.

The above-discussed problems are often-times more acute when there is a need to isolate different zones of formations surrounding a horizontal well. This need arising from the treatment of horizontal wells led to the technology embodied in U.S. Pat. Nos. 7,134,505 and 7,431,091, as well as Publication No. U.S. 200/0151734, published on Jul. 5, 2007. This technology was developed by Packers Plus Energy Services, Inc., located in Calgary, Alberta, Canada, and is widely known as the “Packers Plus” system.

The Packers Plus System uses a plurality of spaced apart packers on a tubing string which, when set, expand out to contact the borehole wall, thus providing a seal or plurality of seals to isolate any fluid movement past such seal or seals. The Packer Plus system also uses fluid bypass ports between the packers to isolate the zones from each other.

Also in the Packer Plus System, a plurality of different diameter ceramic balls are pumped down from the earth's surface to activate a plurality of sliding sleeves which control the opening of the fluid ports. The number of balls can be any number as desired. U.S. Pat. No. 7,134,505, above referenced, has five (5) packers illustrated, but the Packer Plus System sometimes uses nine (9) or more such balls.

It is typical, when using the Packer Plus System, to have one (1), one inch diameter ball, one three and three fourth inch diameter ball, and seven (7) more balls having diameters progressively larger than one inch and smaller than three and three fourth inches. In operation, the smallest diameter ball is pumped down first, and then the next sized ball is pumped down, and so forth, until the largest diameter ball is pumped down. As soon as the treating fluid, for example, a fracturing fluid, has been pumped into the selected formation zones, there arises a need to release and capture the balls at the earth's surface.

The applicant hereby incorporates by reference all the teachings, disclosures, drawings, and abstracts of U.S. Pat. Nos. 7,134,505 and 7,431,091, as well as of Publication No. U.S. 2007/0151734. The description of the following aspects of the present invention constitutes the preferred embodiments of the present invention.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 a is a schematic view of a well which is substantially horizontal to the earth's surface, into which a well-known Packer Plus system has been located to provide frac fluid stimulation or other treatment to the formation surrounding the well;

FIG. 1 b is a schematic, enlarged view of a segment of the system according to FIG. 1 a;

FIG. 1 c is a graphic illustration of a plurality of balls having progressively larger diameters as used in the present invention;

FIG. 2 a is a side view of the ball catcher assembly according to the invention;

FIG. 2 b is an end view of the outlet end of the ball catcher assembly of FIG. 2 a according to the invention;

FIG. 3 is an isometric view of the ball catch assembly according to the invention;

FIG. 4 is a top view of the inlet flange used with the ball catcher assembly according to the invention;

FIG. 5 is a top schematic view of a conventional frac fluid manifold used with the ball catcher assembly according to the invention; and

FIGS. 6 a, 6 b and 6 c are schematic views of alternative embodiments according to the invention of ball catcher assemblies using high pressure fluid to remove balls illustrated in FIG. 1 c from the downhole configuration of FIGS. 1 a and 1 b.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIGS. 1 a, 1 b and 1 c illustrate portions of the technology identified herein above relating to the well-known Packer Plus system for selectively fracturing formations surrounding horizontal oil and gas wells.

Referring further to FIGS. 1 a, 1 b and 1 c, a wellbore fluid treatment assembly is shown, which can be used to effect fluid treatment of a formation 10 through a wellbore 12. The wellbore assembly includes a tubing string 14 having a lower end 14 a and an upper end extending to surface (not shown). Tubing string 14 includes a plurality of spaced apart ported intervals 16 a to 16 e each including a plurality of ports 17 opened through the tubing string wall to permit access between the tubing string inner bore 18 and the wellbore.

A packer 20 a is mounted between the upper-most ported interval 16 a and the surface and further packers 20 b to 20 e are mounted between each pair of adjacent ported intervals. In the illustrated embodiment, a packer 20 f is also mounted below the lower most ported interval 16 e and lower end 14 a of the tubing string. The packers are disposed about the tubing string and selected to seal the annulus between the tubing string and the wellbore wall, when the assembly is disposed in the wellbore. The packers divide the wellbore into isolated segments wherein fluid can be applied to one segment of the well, but is prevented from passing through the annulus into adjacent segments. As will be appreciated the packers can be spaced in any way relative to the ported intervals to achieve a desired interval length or number of ported intervals per segment. In addition, packer 20 f need not be present in some applications.

The packers are of the solid body-type with at least one extrudable packing element, for example, formed of rubber. Solid body packers including multiple, spaced apart packing elements 21 a, 21 b on a single packer are particularly useful especially for example in open hole (unlined wellbore) operations. In another embodiment, a plurality of packers are positioned in side by side relation on the tubing string, rather than using one packer between each ported interval.

Sliding sleeves 22 c to 22 e are disposed in the tubing string to control the opening of the ports. In this embodiment, a sliding sleeve is mounted over each ported interval to close them against fluid flow therethrough, but can be moved away from their positions covering the ports to open the ports and allow fluid flow therethrough. In particular, the sliding sleeves are disposed to control the opening of the ported intervals through the tubing string and are each moveable from a closed port position covering its associated ported interval (as shown by sleeves 22 c and 22 d) to a position away from the ports wherein fluid flow of, for example, stimulation fluid is permitted through the ports of the ported interval (as shown by sleeve 22 e).

The assembly is run in and positioned downhole with the sliding sleeves each in their closed port position. The sleeves are moved to their open position when the tubing string is ready for use in fluid treatment of the wellbore. Preferably, the sleeves for each isolated interval between adjacent packers are opened individually to permit fluid flow to one wellbore segment at a time, in a staged, concentrated treatment process.

Preferably, the sliding sleeves are each moveable remotely from their closed port position to their position permitting through-port fluid flow, for example, without having to run in a line or string for manipulation thereof. In one embodiment, the sliding sleeves are each actuated by a device, such as a ball 24 e (as shown) or plug, which can be conveyed by gravity or fluid flow through the tubing string. The device engages against the sleeve, in this case ball 24 e engages against sleeve 22 e, and, when pressure is applied through the tubing string inner bore 18 from the earth's surface, ball 24 e seats against and creates a pressure differential above and below the sleeve which drives the sleeve toward the lower pressure side.

In the illustrated embodiment, the inner surface of each sleeve which is open to the inner bore of the tubing string defines a seat 26 e onto which an associated ball 24 e, when launched from surface, can land and seal thereagainst. When the ball seals against the sleeve seat and pressure is applied or increased from surface, a pressure differential is set up which causes the sliding sleeve on which the ball has landed to slide to an port-open position. When the ports of the ported interval 16 e are opened, fluid can flow therethrough to the annulus between the tubing string and the wellbore and thereafter into contact with formation 10.

Each of the plurality of sliding sleeves has a different diameter seat and therefore each accept different sized balls. FIG. 1 c graphically illustrates a plurality of such balls, in this example, five such ceramic balls, 24 a, 24 b, 24 c, 24 d and 24 e, with ball 24 a having the largest diameter. The ball 24 a preferably has a diameter of 3¾ inches to pass through pipes or other equipment having an internal diameter of 4 inches. The fifth ball, 24 e, has the smallest diameter of the five balls, preferably 1 inch. The other three balls 24 b, 24 c and 24 d have progressively larger diameters, going from 1 inch to 3¾ inches. However, the number of balls, and their respective diameters are only examples, and are not to be constructed as limiting the present invention. In particular, the lower-most sliding sleeve 22 e has the smallest diameter D1 seat and accepts the smallest sized ball 24 e and each sleeve that is progressively closer to the surface has a larger seat. For example, as shown in FIG. 1 b, the sleeve 22 c includes a seat 26 c having a diameter D3, sleeve 22 d includes a seat 26 d having a diameter D2, which is less than D3 and sleeve 22 e includes a seat 26 e having a diameter D1, which is less than D2. This provides that the lowest sleeve can be actuated to open first by first launching the smallest ball 24 e, which can pass though all of the seats of the sleeves closer to the surface but which will land in and seal against seat 26 e of sleeve 22 e. Likewise, penultimate sleeve 22 d can be actuated to move away from potted interval 16 d by launching a ball 24 d which is sized to pass through all of the seats closer to the surface, including seat 26 c, but which will land in and seal against seat 26 d.

Lower end 14 a of the tubing string can be open, closed or fitted in various ways, depending on the operational characteristics of the tubing string which are desired. In the illustrated embodiment, includes a pump out plug assembly 28. Pump out plug assembly acts to close off end 14 a during run in of the tubing string, to maintain the inner bore of the tubing string relatively clear. However, by application of fluid pressure, for example at a pressure of about 3000 psi, the plug can be blown out to permit actuation of the lower most sleeve 22 e by generation of a pressure differential. As will be appreciated, an opening adjacent end 14 a is only needed where pressure, as opposed to gravity, is needed to convey the first ball to land in the lower-most sleeve. Alternately, the lower most sleeve can be hydraulically actuated, including a fluid actuated piston secured by shear pins, so that the sleeve can be opened remotely without the need to land a ball or plug therein.

In other embodiments, not shown, end 14 a can be left open or can be closed for example by installation of a welded or threaded plug.

While the illustrated tubing string includes five ported intervals, it is to be understood that any number of ported intervals could be used. In a fluid treatment assembly desired to be used for staged fluid treatment, at least two openable ports from the tubing string inner bore to the wellbore must be provided such as at least two ported intervals or an openable end and one ported interval. It is also to be understood that any number of ports can be used in each interval. Centralizer 29 and other standard tubing string attachments can be used.

In use, the wellbore fluid treatment apparatus, as described with respect to FIGS. 1 a, 1 b and 1 c, can be used in the fluid treatment of a wellbore. For selectively treating formation 10 through wellbore 12, the above-described assembly is run into the borehole and the packers are set to seal the annulus at each location creating a plurality of isolated annulus zones. Fluids can then be pumped down the tubing string and into a selected zone of the annulus, such as by increasing the pressure to pump out plug assembly 28. Alternately, a plurality of open ports or an open end can be provided or lower most sleeve can be hydraulically openable. Once that selected zone is treated, as desired, ball 24 e or another sealing plug is launched from the surface and conveyed by gravity or fluid pressure to seal against seat 26 e of the lower most sliding sleeve 22 e. This seals off the tubing string below sleeve 22 e and opens ported interval 16 e to allow the next annulus zone, the zone between packer 20 e and 20 f to be treated with fluid. The treating fluids will be diverted through the ports of interval 16 e exposed by moving the sliding sleeve and be directed to a specific area of the formation. Ball 24 e is sized to pass though all of the seats, including 26 c, 26 d closer to the surface without sealing thereagainst. When the fluid treatment through ports 16 e is complete, a ball 24 d is launched, which is sized to pass through all of the seats, including seat 26 c closer to the surface, and to seat in and move sleeve 22 d. This opens ported interval 16 d and permits fluid treatment of the annulus between packers 20 d and 20 e. This process of launching progressively larger balls or plugs is repeated until all of the zones are treated. The balls can be launched without stopping the flow of treating fluids. After treatment, fluids can be shut in or flowed back immediately. Once fluid pressure is reduced from the surface, any balls seated in sleeve seats can be unseated by pressure from below to permit fluid flow upwardly therethrough. However, such pressure from below is generally not adequate to lift the balls all the way to the ball catcher located at the earth's surface. As used herein, the downhole equipment includes all of the apparatus illustrated and described with respect to FIGS. 1 a and 1 b herein.

The apparatus is particularly useful for stimulation of a formation, using stimulation fluids, such as for example, acid, gelled acid, gelled water, gelled oil, CO₂, nitrogen and/or proppant laden fluids.

Referring now to FIG. 2 a, there is illustrated a ball catcher assembly 40 in accordance with the invention, used to catch the plurality of balls, such as the balls illustrated in FIG. 1 c, once they are lifted off their respective seats, such as the seat 26 e, illustrated in FIG. 1 b.

The ball catcher assembly 40 has a first threaded end 42 sized to threadedly end 42 sized to threadedly connected to one of four inputs of a conventional “FRAC PAC” manifold apparatus hereinafter illustrated in FIG. 5. The first end 42 of the assembly 40 is sized to accept the largest ball, for example, a ball having a 3¾ inch diameter, and of course, accept the smaller diameter balls, for example, going down to the smallest ball of one inch in diameter. The end 42 is connected, through a tapered fitting 44 to a blow down flange 46.

A spool 48 has its first flange 50 bolted to the blow down flange 46. The tapered fitting 44, the flange 46, the spool 48, and each of the flanges 50 and 52 has an internal channel in axial alignment with the opening in the threaded end 42, in which the internal channel accepts the largest diameter ball being lifted out of the earth borehole according to the invention.

The flange 52 is connected to a block 60 having an inlet port 62 and an outlet port 64. The ports 62 and 64 are in a continuous fluid path which may be along a straight line or a curved line, or a square-angled line, or any other configuration, to accommodate the flow of fluid introduced into the inlet 62 to flow out of the outlet 64, and which allows such flowing fluid to transport the plurality of balls entering the end 42 of the ball catcher 40. The interior of the block 60 may simply be a chamber which is in fluid communication with the channel running from the end 42, the inlet port 62 and the outlet port 64. The outlet port 64 is enclosed by a flange 66 connected to the block 60. A third blind flange 68 is provided with a plurality of mounting studs 70.

As illustrated in FIG. 2 b, the outlet port 64 is covered with a steel, or other hard metal screen which allows the pumped fluid coming through the inlet port 62 to exit the block 60. The screen is centered within a steel plate 70 having a center oriface smaller than the largest ball being brought up from downhole, having the built-in feature of breaking up the larger ceramic ball when desired.

FIG. 3 illustrates an isometric view of the ball catching assembly illustrated in FIG. 2, but does not show the blind flange 68 because the blind flange 68 may or may not be used in practicing the invention.

FIG. 4 illustrates a top view of the assembly illustrated as a side view in FIG. 2 a, with FIG. 4 showing the inlet port 62 which is used to pump fluid into the block 60.

FIG. 5 schematically illustrates a conventional manifold 80 used in fracturing formations surrounding oil and gas wells. This type of manifold is sometimes referred to as a “FRAC PAC.”

The uppermost connection point of manifold 80 is a blind flange 82 connected to a manual valve 84, leading to a central flow tee 86 connected to the upper end 88 of tubing string 14 in FIG. 1 a.

In operation, when it is timely to pump frac fluid down to the system illustrated in FIG. 1 a, the service company connects its pumping truck (not illustrated) to the attachment point 82, of FIG. 5, and after opening the valve 84, the frac fluid can be pumped downhole.

The manifold 80 illustrates in FIG. 5 a pair of additional connection points 90 and 100, each tied through a hydraulic valve (92, 104) and a manual valve (94, 106) leading to the control flow tee 86.

The present invention contemplates the use of the one or more ball catchers illustrated in FIGS. 2, 3 and 4 on the same job. When using only one such ball catcher, the ball catcher 40 is threadedly connected by the end 42 to either connector point 90 or connector point 100. When using two ball catchers 40, the threaded end 42 of each is connected to connector points 90 and 100, respectively.

It should be appreciated that when the service to the well has been completed, e.g., which the frac service is done, and when the pressure has been terminated at junction point 82 in FIG. 5, the balls in FIGS. 1 a, 1 b and 1 c will tend to lift off the respective seats due to only a slight pressure of the fluids in the wellbore. However, this downhole pressure is typically not high enough to push the balls back to a ball catcher on the earth's surface. By introducing a high pressure fluid, for example, at equal to or greater than 1,000 psi, but preferably between 5,000 and 10,000 psi, at junction point 90 in FIG. 5, causing the high pressure fluid to come into the inlet 62 of FIG. 2 a. The ball catcher 40 assembly operates as a lifting mechanism, using aspects of Bernoulli's Principle, to pull the balls to the earth's surface as contemplated by the present invention. The amount of pressure downhole and the upward, vacuum-like force caused by the introduction of high pressure fluid to the inlet port 62, work together to lift the balls to the ball catcher 40.

FIG. 6 a diagrammatically illustrates the flow of high pressure fluid into the inlet 62 of FIG. 2 and out of the outlet 64 which causes the balls which had been downhole to be sucked up through the pipe assembly 48, as the high pressure fluid exits the outlet 64. After all of the balls have been brought into the ball catcher, the high pressure fluid can be turned off, and the balls retrieved merely by removing one or more of the flanges 52, 66 or 68.

FIG. 6 b illustrates as alternative embodiment of the invention in which a baffle 65 in the interior of the block 60 deflects the incoming high pressure fluid entering the inlet 62 to bias the flow of such fluid towards the outlet 64 and thereby enhance the lifting mechanism used to retrieve the balls which had been used downhole. The baffle 65 may be nothing more than a bend in the inlet pipe having the inlet 62 at its one end. As an option, such bend may be curved, for example, like a partial circle, to enhance the vacuum effect as illustrated in FIG. 6 c. 

1. A method for retrieving one or more balls from downhole equipment used in the treatment of formations surrounding oil, gas and water wells, comprising the steps of: establishing a first fluid path between the earth's surface and the downhole equipment for moving said one or more balls from the earth's surface to said downhole equipment; establishing a second fluid path between the interior of a ball catcher apparatus at the earth's surface and the downhole equipment for lifting said on or more balls from said downhole equipment to the ball catcher; and establishing a third fluid path for injecting a high pressure fluid into the interior of said ball catcher, whereby the said second fluid path and the said third fluid path intersect within the interior of said ball catcher, thereby providing a lifting force to suck up said one or more balls from the downhole equipment into the ball catcher apparatus.
 2. The method according to claim 1, wherein said second fluid path and said third fluid path intersect at an angle of 90° within the interior of said ball catcher apparatus.
 3. The method according to claim 1, wherein said second fluid path and said third fluid path intersect at an angle, less than 90°, causing fluid in said second and third paths to each be traveling in the same direction away from said downhole equipment.
 4. The method according to claim 1, wherein said high pressure fluid is operated at, at least 1,000 psi.
 5. The method according to claim 1, wherein said high pressure fluid is operated at between 5,000 and 10,000 psi.
 6. A method for retrieving one or more balls from downhole equipment used in the treatment of formations surrounding oil, gas and water wells, comprising the steps of: establishing a first fluid path between the interior of a ball catcher apparatus at the earth's surface and the downhole equipment for lifting said one or more balls from said downhole equipment to the ball catcher apparatus; and establishing a second fluid path for injecting a high pressure fluid into the interior of said ball catcher apparatus, whereby the said second fluid path and the said third fluid path intersect within the interior of said ball catcher, thereby providing a lifting force to suck up said one or more balls from the downhole equipment into the ball catcher apparatus.
 7. The method according to claim 6, wherein said first fluid path and said second fluid path intersect at an angle of 90° within the interior of said ball catcher apparatus.
 8. The method according to claim 6, wherein said first and second fluid path intersect at an angle of less than 90°, causing the fluid in said first and second paths to each be traveling in the same direction away from the downhole equipment.
 9. The method according to claim 6, wherein said high pressure fluid is operated at, at least 1,000 psi.
 10. The method according to claim 6, wherein said high pressure fluid is operated at between 5,000 and 10,000 psi.
 11. A ball catcher system for retrieving and catching one or more balls from downhole equipment used in the treatment of formations surrounding an earth borehole, comprising: a ball catcher having a central chamber at the earth's surface having an inlet portal leading to said central chamber, a high pressure portal leading to said central chamber and an outlet port from said central chamber; a fluid path connected between said downhole equipment to said inlet portal of said ball catcher; and a source of high pressure fluid connected to said high pressure portal, whereby the application of high pressure fluid to said high pressure portal creates a lifting force to at least one ball located in said downhole equipment to suck said at least one ball into the central chamber of said ball catcher.
 12. The system according to claim 11, wherein said at least one ball comprises a plurality of ceramic balls.
 13. The system according to claim 11, where said plurality of ceramic balls each has a different diameter than the remainder of said balls.
 14. The system according to claim 11, wherein said high pressure fluid is operated at, at least 1,000 psi.
 15. The system according to claim 11, wherein said high pressure fluid is operated at between 5,000 and 10,000 psi. 